PVT in Liquid-Rich Shale Reservoirs

Abstract

This paper addresses sampling and PVT modeling of liquid-rich fluids produced from ultra-tight formations – "liquid-rich shale" (LRS) reservoirs.1 Proper PVT treatment in these unconventional reservoirs is important to provide improved short- and long-term oil and gas production forecasts, and define the initial oil and gas in place. We give recommended practices for sampling, laboratory PVT tests, developing PVT (EOS and black-oil) models, and estimating the in-situ reservoir fluid system (composition, saturation, and initial gas-oil ratio). Fluid systems studied include a wide range from lean gas condensates to volatile oils, typical of what is found in the Eagle Ford, Avalon, and other liquid-rich shale plays in North America – with producing oil-gas ratios ranging from 10-1,000 STB/MMscf. LRS producing wellstreams, usually expressed in this paper as a producing oil-gas ratio (OGR) or "liquid yield" 2, are always much leaner than what would be produced from a conventional, higher-permeability reservoir containing the same initial reservoir fluid system. Conventional reservoirs typically produce an initial mixture (for months or years) that is quite similar to the in-situ initial reservoir fluid. The anomalously-low producing OGR of LRS wells is due to very low permeabilities that lead to large drawdowns and fluid flow with localized and large gas-to-oil mobility ratio gradients near the fractures. We show that the loss in oil is a staggering factor of 2 to 50! The liquid yield will be approximately constant from the early days of initial testing throughout the well's entire life. The degree of oil recovery in LRS wells is associated mainly with two issues. First and foremost, whether the reservoir is initially saturated with oil (Soi=1–Swc) or gas (Soi=0). For example, with the in-situ solution OGR of ~350 STB/MMscf (initial GOR of ~3,000 scf/STB), the producing OGR might be 100 STB/MMscf for an oil reservoir (Soi=1–Swc), while it might be less than 10 STB/MMscf for a gas reservoir (Soi=0). Second, for oil LRS reservoirs, oil recovery loss is greatest for near-saturated initial conditions, with oil recoveries increasing as the oil reservoir becomes more undersaturated; degree of undersaturation does not have an impact on the large oil recovery losses seen in all LRS gas reservoirs. Another important result from our study is showing how liquid yield (OGR) evolves with time for LRS wells. It is shown for planar "slab" fracture geometries that the expected infinite-acting behavior is a constant OGR that may last many years or decades. A less-constant intermediate-to-long-term OGR development is found in naturally- or induced-fracture "networks" consisting of a collection of matrix blocks surrounded by fractures. OGR variation depends on network fracture "block" size. The paper shows that it is necessary to combine single-well, finely-gridded numerical modeling of LRS wells to properly develop valid PVT models and in-situ fluid description. Conventional "PVT" sampling and initialization procedures are alone inadequate for liquid-rich shale systems, but additionally require proper treatment of near-well reservoir flow and phase behavior to properly link the significant contrast in producing wellstreams and in-situ fluids. Finally, we propose a special PVT laboratory test for LRS systems.

Production data analysis of tight gas condensate reservoirs

“…This observation is consistent with the findings of Whitson and Sunjerga (2012) and with our mathematical derivations for the linear flow regime. Based on numerical simulations, Whitson and Sunjerga (2012) found that the liquid yield (r p ¼ 1/GOR) remains approximately constant for long periods of constant FBHP in LRS reservoirs. They noted this behavior to be characteristic of LRS reservoirs for the case of infinite-acting flow, when the flow is 1D planar.…”

Nanopore Compositional Modeling in Unconventional Shale Reservoirs

“…They concluded that thermodynamic properties, fluid phase behavior, and IFT between the fluid and pore surface are altered in the nanoporous media. Zarragoicoechea and Kuz (2004) modeled the reduction of critical temperature applying the van der Waals model and reported a good match of their model and the experimental data by Morishige et al (1997). The Zarragoicechea and Kuz (2004) model relates the relative critical-temperature shift quadratically to the ratio of the LJ collision diameter to the pore-throat radius, r LJ =r p (Eq.…”

“…Similarly, Devegowda et al (2012) point out that interactions between molecules and between molecules and pore surface alter the fluid properties because the pore surface available per unit volume increases as the pore size decreases. Zarragoicoechea and Kuz (2004) illustrated that the critical properties of the components should be shifted as a function of the ratio of the molecular size to the pore size. Travalloni et al (2010) state that, as pore size becomes smaller (typically, for pore-to-molecule size less than 20), the thermo-physical and dynamic properties of confined fluids could deviate significantly from the ones measured in the pressure/volume/temperature (PVT) cell.…”

Experimental Study of Permeability Decline in Tight Formations During Long-Term Depletion

“…The work of Whitson and Sunjerga (2012) showed that the depletion behaviors of tight reservoirs depend greatly on reservoir permeability; therefore, the production decline will be impacted by reservoir permeability dynamics during the depletion process. At the very early stage of well production, the entire reservoir is not affected by the depletion and the reservoir energy is at maximum.…”